Apparatus, system, and method for in-situ extraction of oil from oil shale

ABSTRACT

An apparatus, system, and method are disclosed for in-situ extraction of oil from oil shale. The method comprises drilling a fluid conduit in fluid communication with a top and a bottom of a target zone within an oil shale formation. The method includes stimulating the target zone. The method further includes injecting a heated fluid into the bottom of the target zone such that the heated fluid entrains the kerogen within the target zone into the injected fluid to generate a production fluid. The method concludes with producing the production fluid, containing the in-situ kerogen, from the top of the target zone to the surface.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional PatentApplication No. 60/716,647 entitled “Apparatus, system, and method forextracting kerogen from shale with a recirculating fluid” and filed onSep. 14, 2005 for Kevin Shurtleff, which is incorporated herein byreference. This application also claims the benefit of U.S. ProvisionalPatent Application No. 60/820,256 entitled “Apparatus, system, andmethod for in-situ extraction of oil from oil shale” and filed on Jul.25, 2006 for Kevin Shurtleff, which is incorporated herein by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates to the production of oil from oil shale, and moreparticularly relates to stripping in-situ kerogen from an oil shaleformation.

2. Description of the Related Art

One of the last great untapped fossil fuel resources is oil from oilshale. Traditional oil production methods do not pull oil from shalebecause the oil contained within oil shales is stored as kerogen andwill not flow from the shale formation. Kerogen is a high molecularweight hydrocarbon requiring temperatures over 300 degrees C. before itwill break down and separate from the formation rock.

The conventional art for removing oil from oil shale is not economical,requiring shale formations with high oil content, and sustained high oilprices. For example, the oil shale deposits in Eastern Utah vary between10 and 60 gallons of oil per ton of shale formation, and mostconventional practices are only projected to be profitable above 25gallons of oil per ton, meaning many formations are not suitable forthese practices. Therefore, commercial oil shale production is not yetavailable on a large scale.

One example of a conventional practice for oil shale production is anin-situ conversion process (ICP) developed by Shell. In the ICP process,a large number of wells are drilled around a target zone, and arefrigerant is circulated through these wells to create an ice sealaround the target zone and prevent formation water from migrating intothe target zone. Then, two wells are drilled into the center of thetarget zone. The water already within the target zone is pumped out, anelectric heater is placed within one of the wells, and oil is pumped outthe other well as it is heated.

The ICP process covers the basic principles needed to remove oil fromoil shale. First, the water in the target zone must be removed ordisplaced to allow the temperature in the target zone to reach therequired level. Then, a large amount of thermal energy is requiredbefore the oil can be extracted. The ICP process has the disadvantage ofrequiring a large number of drilled wells, as well as the pumping lossesand cooling requirements of the refrigerant wells.

Another example of a conventional practice for oil shale production is astrip mining process. An oil shale formation is mined and the bulkmaterial treated at the surface to remove the kerogen. While thisprocess is simple, it introduces a number of environmental issues whichmust be resolved. First, strip mining itself changes the landscapedramatically, and it can require many years before the land is againavailable for other purposes. Second, the bulk oil shale material, evenwhen stripped of kerogen, may contain oil and chemical residues thatpresent a disposal problem.

Another example of a conventional practice for oil shale production isan underground room and pillar mining process. The process is expensiveand leaves significant amounts of kerogen in place as support for themining chambers. The process is only economical in shallow shales(perhaps less than 1000 feet deep) and it requires minimum formationthicknesses of 50 to 100 feet. Again the bulk oil shale materialrequires disposal in this mining process.

From the foregoing discussion, it should be apparent that a need existsfor an apparatus, system, and method that allows for the economicremoval of oil from oil shale. Beneficially, such an apparatus, system,and method would strip the oil from the shale in-situ, and maximize theefficiency of the large amounts of thermal energy required to remove theoil from the shale formation.

SUMMARY OF THE INVENTION

The present invention has been developed in response to the presentstate of the art, and in particular, in response to the problems andneeds in the art that have not yet been fully solved by currentlyavailable oil shale extraction systems. Accordingly, the presentinvention has been developed to provide an apparatus, system, and methodfor extracting oil from oil shale that overcome many or all of theabove-discussed shortcomings in the art.

An apparatus is disclosed for extracting oil from oil shale. Theapparatus may include a drilling unit for drilling a well to fluidlycommunicate with the top and bottom of a target zone of an oil shaleformation. The apparatus may also include a stimulation moduleconfigured to stimulate the target zone. The apparatus may furtherinclude a completion unit configured to position an injection tubesubstantially at the bottom of the target zone, and an injection unitconfigured to inject a fluid into the target zone. The injection unitmay be configured to inject the fluid into the target zone such that thefluid displaces free water within the target zone. The injected fluidmay be commercial natural gas and/or produced natural gas from the well.

The apparatus may include a thermal delivery unit configured to heat thefluid such that the heated fluid entrains in-situ kerogen to generate aproduction fluid. The thermal delivery unit may be configured to heatthe fluid at the surface using a solar concentrator and/or a gas burner.The thermal delivery unit may comprise a downhole burner configured toheat the fluid in the well without introducing combustion byproductsinto the fluid. In one embodiment, the apparatus may include acirculation unit to circulate the fluid through an offset well topreheat the fluid before heating of the fluid by the thermal deliveryunit.

The apparatus may further include a production module, which maybe atube, to produce the production fluid. The apparatus may include atreatment module configured to heat the production fluid to a targettemperature, add natural gas to provide excess hydrogen if needed, andreact the production fluid on a catalytic reactor. The treatment modulemay thus break the hydrocarbons of the production fluid into smaller,more commercially valuable hydrocarbons.

The stimulation module may be further configured to stimulate a secondtarget zone, which may be in the well in a higher location than thefirst target zone. The completion unit may be configured to position theinjection tube substantially at the bottom of the second target zone.The apparatus may further include an isolation unit configured toisolate the well from the first target zone. The injection unit may befurther configured to inject the fluid into the second target zone. Thethermal delivery unit may be further configured to heat the fluid suchthat energy of the heated fluid entrains in-situ kerogen within thesecond target zone to generate the production fluid.

A method is disclosed for extracting oil from oil shale. The method maycomprise drilling a well to fluidly communicate with the top and bottomof a target zone. The well may include one or more wells, and thewell(s) may be vertical or horizontal wells. The method may furtherinclude stimulating the target zone, and positioning an injection tubesubstantially at the bottom of the target zone. The method may theninclude injecting a fluid into the target zone, and heating the fluidsuch that the heated fluid entrains in-situ kerogen to generate aproduction fluid. The method may include producing the production fluid.The method may conclude with heating the production fluid to a targettemperature and treating the production fluid in a catalytic reactor toreduce the average molecular weight of the entrained kerogen. The methodmay further comprise adding natural gas to the production fluid suchthat a minimal amount of hydrogen is available for reaction within thecatalytic

In one embodiment, the method may include positioning a production tubesubstantially at the top of the target zone, where producing theproduction fluid comprises flowing the production fluid up theproduction tubing. The method may include setting a production casingthrough the oil shale formation, and perforating the production casingsubstantially near the bottom of the target zone, perforating theproduction casing substantially near the top of the target zone. Wherethe method includes a production casing, positioning the injection tubefurther comprises positioning the injection tube within the productioncasing, and producing the production fluid may comprise flowing theproduction fluid up the annulus formed between the production casing andthe injection tubing. Flowing the production fluid up the annulus formedbetween the production casing and the injection tubing may includepositioning a production tube within the annulus, and producing theproduction fluid up the production tube.

A system is disclosed for in-situ extraction of oil from oil shale. Thesystem may include a three-phase separator configured to separate aproduction fluid into oil, water, and natural gas, and fluid couplingconfigured to deliver separated water to a water disposal system, todeliver separated oil to an oil storage facility, and to deliverseparated natural gas to a natural gas storage facility. The system mayfurther include a drilling unit for drilling a well to fluidlycommunicate with the top and bottom of a target zone of an oil shaleformation. The system may also include a stimulation module configuredto stimulate the target zone. The system may further include acompletion unit configured to position an injection tube substantiallyat the bottom of the target zone, and an injection unit configured toinject a fluid into the target zone. The injection unit may beconfigured to inject the fluid into the target zone such that the fluiddisplaces free water within the target zone. The injected fluid may becommercial natural gas and/or produced natural gas from the well.

The system may further include a production module, which maybe a tube,to produce the production fluid. The system may include a treatmentmodule configured to heat the production fluid to a target temperature,add natural gas to provide excess hydrogen if needed, and react theproduction fluid on a catalytic reactor. The treatment module may thusbreak the hydrocarbons of the production fluid into smaller, morecommercially valuable hydrocarbons. The system may also include acondensing module configured to cool the reacted production fluid anddeliver the cooled fluid to the three-phase separator.

Reference throughout this specification to features, advantages, orsimilar language does not imply that all of the features and advantagesthat may be realized with the present invention should be or are in anysingle embodiment of the invention. Rather, language referring to thefeatures and advantages is understood to mean that a specific feature,advantage, or characteristic described in connection with an embodimentis included in at least one embodiment of the present invention. Thus,discussion of the features and advantages, and similar language,throughout this specification may, but do not necessarily, refer to thesame embodiment.

Furthermore, the described features, advantages, and characteristics ofthe invention may be combined in any suitable manner in one or moreembodiments. One skilled in the relevant art will recognize that theinvention may be practiced without one or more of the specific featuresor advantages of a particular embodiment. In other instances, additionalfeatures and advantages may be recognized in certain embodiments thatmay not be present in all embodiments of the invention.

These features and advantages of the present invention will become morefully apparent from the following description and appended claims, ormay be learned by the practice of the invention as set forthhereinafter.

BRIEF DESCRIPTION OF THE DRAWINGS

In order that the advantages of the invention will be readilyunderstood, a more particular description of the invention brieflydescribed above will be rendered by reference to specific embodimentsthat are illustrated in the appended drawings. Understanding that thesedrawings depict only typical embodiments of the invention and are nottherefore to be considered to be limiting of its scope, the inventionwill be described and explained with additional specificity and detailthrough the use of the accompanying drawings, in which:

FIG. 1 is a schematic block diagram depicting one embodiment of a systemfor removing oil from oil shale in accordance with the presentinvention;

FIG. 2 is a schematic block diagram depicting one embodiment of at leastone fluid conduit to a top of a target zone and a bottom of a targetzone of an oil shale formation;

FIG. 3 is a schematic block diagram depicting one embodiment of atreatment module in accordance with the present invention;

FIG. 4 is a schematic block diagram depicting one embodiment of adownhole burner in accordance with the present invention;

FIG. 5 is an illustration of one embodiment of a second target zone inaccordance with the present invention;

FIG. 6 is a schematic block diagram depicting an alternate embodiment ofa at least one fluid conduit to a top and a bottom of a target zone inaccordance with the present invention;

FIG. 7 is a schematic block diagram depicting one embodiment of heatinga hydrocarbon gas in accordance with the present invention;

FIG. 8A is a schematic block diagram depicting one embodiment of a firstand second horizontal well segment in accordance with the presentinvention;

FIG. 8B is a schematic block diagram depicting an alternate embodimentof a first and second horizontal well segment in accordance with thepresent invention;

FIG. 9 is a schematic block diagram depicting one embodiment of a first,second, and third horizontal well segment in accordance with the presentinvention;

FIG. 10A is an illustration of a well spacing in accordance with thepresent invention;

FIG. 10B is an illustration of an alternate well spacing in accordancewith the present invention;

FIG. 11 is an illustration of a thermodynamic equilibrium chart forheavy hydrocarbons in the absence of excess hydrogen;

FIG. 12 is an illustration of a thermodynamic equilibrium chart forheavy hydrocarbons in the presence of excess hydrogen;

FIG. 13 is a schematic flow diagram of a method for extracting oil fromoil shale in accordance with the present invention;

FIG. 14A is a schematic flow diagram of a method for extracting oil froman oil shale comprising a first and second target zone in accordancewith the present invention;

FIG. 14B is a schematic flow diagram of a method for extracting oil froman oil shale comprising a first and second target zone in accordancewith the present invention;

FIG. 15A is a schematic flow diagram of a method for extracting oil froman oil shale, the method comprising drilling at least one horizontalwell segment, in accordance with the present invention; and

FIG. 15B is a schematic flow diagram of a method for extracting oil froman oil shale, the method comprising drilling at least one horizontalwell segment, in accordance with the present invention.

DETAILED DESCRIPTION OF THE INVENTION

It will be readily understood that the components of the presentinvention, as generally described and illustrated in the figures herein,may be arranged and designed in a wide variety of differentconfigurations. Thus, the following more detailed description of theembodiments of the apparatus, system, and method of the presentinvention, as presented in FIGS. 1 through 15B, is not intended to limitthe scope of the invention, as claimed, but is merely representative ofselected embodiments of the invention.

Reference throughout this specification to “one embodiment” or “anembodiment” means that a particular feature, structure, orcharacteristic described in connection with the embodiment is includedin at least one embodiment of the present invention. Thus, appearancesof the phrases “in one embodiment” or “in an embodiment” in variousplaces throughout this specification are not necessarily all referringto the same embodiment.

Furthermore, the described features, structures, or characteristics maybe combined in any suitable manner in one or more embodiments. In thefollowing description, numerous specific details are provided, such asexamples of materials, fasteners, sizes, lengths, widths, shapes, etc.,to provide a thorough understanding of embodiments of the invention. Oneskilled in the relevant art will recognize, however, that the inventioncan be practiced without one or more of the specific details, or withother methods, components, materials, etc. In other instances,well-known structures, materials, or operations are not shown ordescribed in detail to avoid obscuring aspects of the invention.

FIG. 1 is a schematic block diagram depicting one embodiment of a system100 for removing oil from oil shale in accordance with the presentinvention. The system 100 may comprise a three-phase separator 102configured to separate a production fluid into oil, water, and naturalgas. The system 100 may further include fluid coupling 104 configured todeliver separated water to a water disposal system 106, to deliverseparated oil to an oil storage facility 108, and to deliver separatednatural gas to a natural gas storage facility 110.

The system 100 may further comprise a drilling unit 112 configured todrill at least one fluid conduit to a top of a target zone and a bottomof the target zone of an oil shale formation. The fluid conduit(s) to atop of a target zone and a bottom of the target zone of an oil shaleformation may comprise a well 114. The well 114 may comprise one or morevertical wells 114, and/or one or more horizontal wells 114. The targetzone may comprise a region within an oil shale formation from which thesystem 100 will remove the oil from the oil shale. Some of the detailsof one embodiment of a well 114 are shown in FIG. 2 for clarity. Thedrilling unit 112 may comprise a coiled-tubing drilling unit, or astandard drilling rig.

The system 100 may further comprise a stimulation module 116. Thestimulation module 116 may comprise an explosive device, a hydraulicfracturing unit, a matrix acid unit, and/or other stimulation unitsknown in the art. In one example, the stimulation module 116 comprisesan explosive device configured to detonate within the target zone, andcreate a semi-spherical fractured region around the wellbore of the well114, with approximately a 90 foot radius and a 45 foot height. Thestimulation module 116 may comprise multiple explosive devices dependingupon the fracture capability of a given device, and the size of theintended target zone.

The system 100 may further comprise a completion unit 118 configured toposition an injection tube substantially at the bottom of the targetzone. Positioning as used herein describes the placement and positioningof the injection tube outlet, where the injection tube inlet may be atthe wellhead of the well 114, at the surface, on a coiled tubing unit,or at some other location depending upon the specific embodiment of theinvention. The completion unit 118 may comprise a workover rig, acompletion rig, or a coiled tubing unit. Any other type of tubingplacement equipment suitable to place injection tubing in the well 114is considered a completion unit 118 within the scope of the invention.

The system 100 may have an injection unit 120 configured to inject afluid 122 into the target zone. The fluid 122 may comprise any gascompatible with the formation, and may typically comprise natural gas,nitrogen, water vapor, and carbon dioxide. Without limitation, the fluid122 may also comprise carbon monoxide, helium, hydrogen, argon, neon,methane, ethane, propane, butane, and the like. The injection unit 120may be configured to inject the fluid 122 into the target zone such thatthe fluid 122 displaces free water within the target zone 210 (see FIG.2). In one embodiment, the fluid 122 is injected at a pressure higherthan a fluid pressure of the formation and lower than a fracturepressure of the formation. In one example, an oil shale formationcomprises a fluid formation pressure of about 1300 psig, and a fracturepressure of about 2100 psig, at a formation depth of about 3000 feet.

The injection pressure for displacement of free water is measured at theformation depth (the “downhole pressure”). It is within the skill of onein the art to estimate the downhole pressure from the surface pressure,or to place a downhole pressure device in formations where smalldifferences between the fracturing pressure and the formation fluidpressure require greater accuracy than surface estimates allow.

The system 100 may include a thermal delivery unit 124 configured toheat the fluid 122 such that the heated fluid 122 entrains in-situkerogen to generate a production fluid 126. The system 100 may include atreatment module 128 configured to heat the production fluid 126 to atarget temperature and to react the production fluid 126 in a catalyticreactor. Further details of one embodiment of a treatment module 128 areprovided in reference to FIG. 3. The system 100 may further include acondensing module 130 configured to cool the production fluid 126 and todeliver the reacted production fluid 126 to the three-phase separator102.

The thermal delivery unit 124 may be configured to heat the fluid 122 atthe surface as shown in the embodiment of FIG. 1, or to heat the fluid122 closer to the target zone, for example within the well 114. Thethermal delivery unit 124 may include an oil heater 132 configured toreceive heat from a natural gas burner 134, and/or from a solarconcentrator 136. The thermal delivery unit 124 may further include aheat exchanger 138 configured to transfer the heat from the oil heater132 to the fluid 122. The unit 124 may cycle oil from an oil sump 140,through the oil heater 132, and through the heat exchanger 138, beforereturning the oil to the oil sump 140. Other methods of collecting heatfrom the natural gas burner 134 and/or the solar concentrator 136 areknown in the art, and these are contemplated within the scope of theinvention.

The heated fluid 122 entrains in-situ kerogen over a period of time. Thefluid 122 begins heating the formation from the well 114 outward intothe target zone 210 of the formation. After a period of time, thekerogen breaks down, releases from the oil shale, and is entrained intothe fluid 122 to generate the production fluid 126. Eventually, theentire target zone 210 treated by the injection of the fluid 122 becomessubstantially depleted of kerogen, and the oil cut of the productionfluid 126 drops to the point where further operation of the system 100to remove oil from the oil shale is no longer economical.

In one example for general guidance, using methane at 400 degrees C. asthe heated fluid 122, the fluid 122 is injected at 2,300 cubic feet perminute, and approximately 60% of the in-situ kerogen from the targetzone is estimated to be extracted from a well 114 draining a 0.72 acrearea, with a 100 foot thick target zone, within one year. The exacttemperatures, injection rates, and depletion times depend upon thecharacteristics of the individual formation and kerogen within thatformation, the specific costs of drilling, heating, and pumping thefluid 122 and are calculations within the skill of one in the art inlight of the disclosures herein.

Generally, temperatures below 300 degrees C. may not break down andentrain kerogen except in oil shale formations where the kerogen mayhave a very low base molecular weight. Consequently, the system 100operates with a preferred temperature for the fluid above 300 degrees C.Economic considerations such as the desired time to produce a targetzone to depletion may drive the temperature determination even higherthan 400 degrees C. which will break down and entrain most kerogens.These determinations can be made from a simple core sample test of theoil shale formation and the economics of a given embodiment of thesystem 100, and are within the skill of one in the art.

The system 100 may include a production module (shown in FIG. 2)configured to produce the production fluid 126 from the formation to thesurface. In the context of the present invention, producing theproduction fluid 126 means flowing the production fluid 126 to thesurface, either through the inherent pressure within the fluid 126, orthrough artificial means such as pumping or the like.

The natural gas storage facility 110 may be configured to providenatural gas to the natural gas burner 134, to provide natural gas to theinjection unit 120, perhaps through the heat exchanger 138, and toprovide natural gas to the treatment module 128. The natural gas storagefacility 110 may be connected to an external gas source through acontrol valve 142, and may be configured to receive gas from theexternal gas source, or to deliver excess produced gas to the externalgas source.

The system 100 may comprise various temperature, pressure, and fluiddensity sensors, control valves, and electronic or other controls toutilize these features. These sensors and controls are known in the art,and are omitted from the system 100 shown in FIG. 1 to avoid obfuscatingfeatures of the illustrated embodiment of the invention.

FIG. 2 is a schematic block diagram depicting one embodiment of at leastone fluid conduit 114 to a top of a target zone and a bottom of a targetzone of an oil shale formation, where the at least one fluid conduit inFIG. 2 comprises a well 114. The features shown in FIG. 2 indicatefunctional relationships only and are not drawn to scale. For example,the depth of the oil shale formation 212 from the surface may vary fromnear the surface to several thousand feet. The well 114 may include awellhead 202 configured to allow the introduction and expulsion offluids from the well 114, and to contain any pressure from the well 114.The well 114 may form a fluid conduit 204 to the top of a target zone210 of an oil shale formation 212, and a fluid conduit 206 to the bottomof the target zone 210 of the oil shale formation 212.

The stimulation module 116 may be configured to stimulate the targetzone 210, and thereby create at least one stimulated region 214. In oneembodiment, a fractured semi-spherical region 214 is created from anexplosive fracturing device. Where the target zone 210 is taller thanthe stimulated region 214 from a single explosive device, multipleexplosions may be used to stimulate as much of the target zone 210 aseconomic considerations dictate. In the example shown in FIG. 2, thestimulation module 116 created two stimulated regions 214 each about 45feet tall and 90-foot radius, where the target zone 210 is about 100feet thick (tall) and 200 feet in diameter.

The well 114 may include a production module 216 configured to producethe production fluid 126. The production module 216 may be a productiontube 216 positioned substantially at the top of the target zone 210.Ideally, the production module 216 will draw fluid from the target zone210 at the top of the target zone 210, but design considerations andphysical constraints of the system 100 may require the production module216 to draw fluid from above or below the top of the target zone withoutdetriment to the functioning of the present invention.

For example, in deep wells the exact placement of the end of theproduction tube 216 may be uncertain to within a range of several feetwithout the use of expensive logging tools to place the end of the tube216. The invention does not require that such error be accounted for. Inanother example, the system 100 may be designed such that a secondtarget zone (refer to FIG. 5) will be completed above the first targetzone 210 at a later time. In the example, the placement of theproduction tube 216 may be 10 feet (or more) above or below the top ofthe target zone 210 to allow for a cement plug or other isolationmechanism to isolate the first and second target zones. These allowancesare within the margin indicated by a production tube 216 positionedsubstantially at the top of the target zone 210.

The system 100 may include an injection tube 218 positioned within thewell 114 substantially at the bottom of the target zone 210 of the oilshale formation 212. As with the production tube 216, the exactplacement of the injection tube 218 is not critical, although ideally aposition at the bottom of the target zone 210 is desirable. Theinjection unit 120 may further comprise isolation 220 within the well114, such that injected fluid 122 enters the target zone 210. Theisolation 220 may comprise a cement plug, a pair of bridge plugs—one atthe top and one at the bottom of the region 220—or the like.

In one embodiment, the fluid 122 comprises a fluid heated at thesurface, and the injection tube 218 comprises a vacuum insulated tube.The vacuum insulated tubing may comprise a k-factor of 0.006 to 0.02BTU/hr-ft-degF, or about 5000 times lower than the k-factor of standardproduction steel tubing. The fluid 122 may be heated at the surfaceusing combusted natural gas (134, 132, 138), a solar concentrator 136,and/or through recirculation of the fluid 122 through an offset depletedwell (see FIG. 7).

The well 114 may include an upper isolation 222 configured to preventexposure of the backside of the production tube 216 to the productionfluid 126. The upper isolation 222 is not necessary for the properfunction of the invention, but in some embodiments the upper isolation222 may be desirable to protect the production tube 216 from unnecessaryexposure to contaminants.

The embodiment of FIG. 2 illustrates an open-hole completion, or aproducing well 114 without casing set through the target zone 210. Thewell 114 may be a cased well, as indicated by an embodiment of a well114 illustrated in FIG. 6.

FIG. 3 is a schematic block diagram depicting one embodiment of atreatment module 128 in accordance with the present invention. Thetreatment module 128 may be configured to heat the production fluid 126to a target temperature and to react the production fluid in a catalyticreactor 302. This reduces the average molecular weight of the entrainedkerogen in the production fluid 126. A typical kerogen will exceedtwenty carbons per hydrocarbon molecule, although the extracted kerogenwill also produce a significant amount of natural gas which is generallyconsidered one to four carbons per molecule. Hydrocarbons roughly aroundten carbons per molecule are generally much more commercially desirablethan the large hydrocarbons over twenty carbons per molecule.

In one embodiment, the treatment module 128 receives natural gas 304from the natural gas storage facility 110, combusts the natural gas in aburner 306, and heats the production fluid 126 in a heat exchanger 308with the combusted gas 310. The amount of gas 304 to be combusted willdepend upon the mass and heat capacity of the production fluid 126, theenergy in the gas 304, the efficiency of the burner 306 and heatexchanger 308, and the target temperature. The sensors and controls toimplement the heating controls are known in the art and not describedherein to avoid obscuring aspects of the invention.

The treatment module 128 may include scrubbing contaminants from theproduction fluid 126 before treating the production fluid 126 in thecatalytic reactor 302. Among the contaminants which may be present inthe production fluid 126 are sulfur compounds, nitrogen compounds, andheavy metals or metalloids such as arsenic. The scrubbing may beperformed before or after heating the production fluid 126 in the heatexchanger 308, although separating before heating may lower the heatburden of the heat exchanger 308. Various scrubbing systems are known inthe art.

The treatment module 128 may be configured to react the production fluid126 in a catalytic reactor 302 after heating. A standard platinum-basedcatalyst may be used in the catalytic reactor 302, although manycatalytic systems are known that lower the activation energy of thehydrocarbon cracking reaction and thereby reduce the time tothermodynamic equilibrium. These systems are contemplated within thescope of the invention. Catalyst selection and sizing of the reactor 302depends upon the specific composition of the production fluid 126. Thecatalyst and sizing selections are within the skill of one in the art,and can be determined for a particular production fluid 126 with simpleand straightforward field experiments.

When cracking large hydrocarbon molecules into smaller hydrocarbonmolecules, the presence of excess available hydrogen makes smallerhydrocarbons the favored thermodynamic product. To ensure thethermodynamics favor the production of small hydrocarbons, where theproduction fluid 126 does not contain enough methane and other light-endhydrocarbon gases, the treatment module 128 may add natural gas 304 tothe production fluid 126 before heating in the heat exchanger 308. Inone embodiment, a preferred ratio is at least one free methane for eachlarge hydrocarbon molecule, or about 5% by weight methane. The ratiosfor specific embodiments vary with the compositions of the availablenatural gas 304, the production fluid 126, the target temperature, andthe catalyst type and loading on the reactor 302, and can be calculatedby one of skill in the art based on the data for the contemplatedembodiment and the disclosures herein.

FIG. 4 is a schematic block diagram depicting one embodiment of adownhole burner 402 in accordance with the present invention. Thethermal delivery unit 124 may comprise a downhole burner 402 configuredto heat the fluid 122 within the at least one fluid conduit (the well114) to the bottom of the target zone 210. The downhole burner 402 maycombust a heating fluid 404 within the well 114. The heating fluid 404may comprise a mixture of natural gas and oxygen (or air). The burner402 may pass the combusted heating fluid 406 through a heat exchanger408 to heat the fluid 122 in the injection tube 218.

The use of a downhole burner 402 may be combined with surface heating ofthe thermal conduit fluid 124 and/or vacuum insulated tubing 218.Without limitation, the combination is especially appropriate withpassive heating mechanisms such as the use of solar concentrators 136and recirculation through an offset well (see FIG. 7). In oneembodiment, the majority of the injection tube 218 comprises vacuuminsulated tubing, while the tube section exposed to the heat exchanger408 comprises standard tubing.

FIG. 5 is an illustration of one embodiment of a second target zone 502in accordance with the present invention. The stimulation module 116 maybe further configured to stimulate 514 the second target zone 502, andthe completion unit 118 may be further configured to position theinjection tube 218 substantially at the bottom of the second target zone502. The system 100 may further comprise an isolation unit (not shown)configured to isolate 504 the portion of the fluid conduit 114 in fluidcommunication with the first target zone 210 from the portion of thefluid conduit 114 in fluid communication with the second target zone502. The isolation unit may comprise a cementing unit configured toplace a cement plug 504, and/or a completion unit 118 to place a bridgeplug 504.

The injection unit 120 may inject the fluid 122 into the second targetzone 502. The thermal delivery unit 124 heats the fluid 122 such thatthe energy of the heated fluid 122 entrains in-situ kerogen in the fluid122 to generate the production fluid 126.

In the example of FIG. 5, the completion unit 118 may be configured toisolate 522 the production tube 216 from the wellbore above the secondtarget zone 502, and to isolate 520 the injection tube 218 from theproduction tube 216 such that the injected fluid 122 flows through thesecond target zone 502. The injection tube 218 maybe configured toinject the fluid 122 above or below a prior isolation 222 for the firsttarget zone 210. The injection tube 218 is shown in the exampleinjecting the fluid 122 below the previous isolation 222.

FIG. 6 is a schematic block diagram depicting an alternate embodiment ofat least one fluid conduit 114 to a top and a bottom of a target zone210 in accordance with the present invention. The primary difference inthe embodiment of FIG. 6 from the embodiment of FIG. 2 is that theembodiment of FIG. 2 is an open-hole completion while the embodiment ofFIG. 6 is a completion with casing 602 set within the target zone 210,and wherein the fluid communication between the fluid conduit(s) 114 tothe top and bottom of the target zone 210 comprises perforations 204,206 through the casing 602 (and supporting cement layer, if any) andinto the target zone 210.

In the embodiment of FIG. 6, the stimulation module 116 may comprise ahydraulic fracturing unit configured to fracture the target zone 210 andenhance the flow of the fluid 122 into the target zone 210. Thestimulation module 116 may comprise an explosive device.

In one embodiment of FIG. 6 when the stimulation module 116 comprises anexplosive device, the system 100 may be configured such that thedrilling unit 112 drills through the target zone 210, the stimulationmodule 116 stimulates the target zone 210 with an explosion, thecompletion unit 118 sets casing 602 across the target zone 210, cementsthe casing 602, and forms perforations 204, 206 through the casing 602.In the example, the stimulation module 116 may be further configured tostimulate the target zone 210 near the wellbore to connect theperforations 204, 206 to the stimulated target zone 210. The nearwellbore stimulation may involve a hydraulic fracturing treatment, amatrix acid treatment, or the like to reconnect the perforations 204,206 to the previously fractured target zone 210.

The production module 216 may flow the production fluid 126 directly upthe annulus between the injection tubing 218 and the casing 602. In theembodiment of FIG. 6, the production fluid 126 is flowed up a productiontube 216 within the annulus between the injection tubing 218 and thecasing 602.

FIG. 7 is a schematic block diagram depicting one embodiment of heatinga fluid 122 in accordance with the present invention. The system 100 maycomprise a circulation unit (not shown) configured to circulate thefluid 122 through an offset well 702 near the production well 114. Theoffset well 702 may comprise a depleted zone 704, which may be a zonewithin an oil shale formation 212 which may already be depleted ofproduction products, or kerogen. As used herein, offset indicates a wellconnected to a depleted zone 704 that is not the target zone 210intended for production. The well connected to the target zone 210 maybe called the producing well. The offset well may be an adjacent well tothe producing well, a well completely across the field from theproducing well, or a separate horizontal branch within the producingwell, where the separate horizontal branch is in fluid communicationwith the depleted zone 704, but is fluidly isolated—except for theintended delivery of the heated fluid 124 from the injection unit120—from the target zone 210.

After circulation through the offset well, the fluid 122 may then befurther heated in the system 100 or injected by the injection unit 120.The base temperature in the formation 704 is often much higher than theambient surface temperature, and a significant savings in thermal energycosts can be achieved through heating the fluid 122 according to theembodiment of FIG. 7.

FIG. 8A is a schematic block diagram depicting one embodiment of a first802 and second 804 horizontal well segment in accordance with thepresent invention. The horizontal well segments 802, 804 share manyfeatures with the vertical well 114 descriptions of FIGS. 2 and 6,including the function of the stimulation module 116 and other features.Therefore, the description of FIG. 8A should be read to be additive tothose descriptions, and only to highlight a few differences that may bepresent in embodiments of the present invention that utilize one or morehorizontal well segments.

The at least one fluid conduit 114 may comprise a first horizontal wellsegment 802 and a second horizontal well segment 804. The firsthorizontal well segment 802 may be in fluid communication with the topof the target zone 210, and the second horizontal well segment 804 maybe in fluid communication with the bottom of the target zone 210. Thesystem 100 may comprise an injection tube 218 positioned substantiallyat the bottom of the target zone 210, and a production tube 216positioned substantially at the top of the target zone 210.

The system 100 may further include a second target zone 502. The system100 may include a first isolation unit 806 and a second isolation unit808 configured such that the injection tube 218 and production tubes 216are fluidly isolated from the second production zone 502. The well 114completion of FIG. 8A maybe an openhole completion or a cased completionwherein the casing 602 is perforated.

The first target zone 210 may comprise a horizontal width equivalent tothe thickness (height) of the first target zone 210. Such parameters aredesirable because the fluid 122 injected at the injection tube 218 intothe first target zone 210 generally propagates as a normally distributedcurve within the target zone 210, reaching a horizontal widthapproximately equal to the height of the target zone 210 by the time thefluid 122 propagates to the height of the target zone 210 (see FIG. 10).

However, specific embodiments may vary considerably from this generalguideline. For example, the horizontal length of the first and secondhorizontal segments 802, 804 may be 225 feet, and the height of thetarget zone 210 may be 100 feet. In such an example, splitting the oilshale formation 212 into two target zones 210, 502 of 112.5 feet eachwith none of the oil shale formation left completely untreated willyield better oil recovery than two target zones 210, 502 of 100 feeteach, with 25 feet of the oil shale formation left untreated. In anotherexample, the horizontal length of the first and second horizontalsegments 802, 804 may be 200 feet, and the height of the target zone 210may be 100 feet. For the purposes of the example, if the oil content ofthe formation 212 is relatively high, and the price of oil is relativelyhigh, the costs of completing and producing additional target zoneswithin the formation 212 may be lower than the enhanced recovery byusing shorter target zones. Therefore, splitting the oil shale formation212 into three target zones 210, 502, (not pictured) axially along thehorizontal segments 802, 804 may yield better economic recovery from thewell 114 than two target zones 210, 502 at 100 feet each.

Where the target zone width is greater than the target zone height, theoil recovery will be lower, but the unit cost of production will belower. Where the target zone width is lower than the target zone height,the oil recovery will be higher, but the unit cost of production will behigher. The selection of target zone 210, 502 lengths along thehorizontal segments 802, 804 of the well is a similar exercise todetermining the economic well spacing in embodiments using a verticalwell 114, discussed later. These economic considerations are within theskill of one in the art to determine optimal target zone 210, 502spacing based upon the production costs associated with a particularembodiment of the system 100, the oil content of the formation 212, andthe disclosures herein, including the discussions referencing FIGS. 10Aand 10B.

FIG. 8B is a schematic block diagram depicting an alternate embodimentof a first and second horizontal well segment 802, 804 in accordancewith the present invention. FIG. 8B illustrates an embodiment where thefirst horizontal well segment 802 is associated with a first well 114,and the second horizontal well segment 804 is associated with a secondwell 810. The information relating to the embodiment of FIG. 8Aotherwise applies to the embodiment of FIG. 8B, and is not included toavoid unnecessary repetition.

FIG. 9 is a schematic block diagram depicting one embodiment of a first,second, and third horizontal well segment 802, 804, 902 in accordancewith the present invention. The embodiment of FIG. 9 may be used todevelop two target zones 210, 502 utilizing horizontal well segments802, 804, 902 wherein the target zones 210, 502 are aligned vertically,i.e. one target zone is above the other. In the embodiment of FIG. 9,the drilling unit 112 may be further configured to drill a thirdhorizontal segment 902 fluidly coupled to the top of the second targetzone 502.

The first horizontal segment 802 may be in fluid communication with thebottom of the second target zone 502. The stimulation module 116 maystimulate the second target zone 502. The completion unit 118 mayposition the injection tube 218 substantially at the bottom of thesecond target zone 502. The injection unit 120 may inject the fluid 122into the second target zone 502. The thermal delivery unit 124 may heatthe fluid 122 such that the heated fluid entrains in-situ kerogen fromthe second target zone 502 to generate the production fluid 126. Theisolation unit (not shown) may be further configured to isolate thefluid conduit 114 from the first target zone 210, for example by placinga cement plug and/or a bridge plug in the second horizontal segment 804.The production module 216 may be configured to produce the productionfluid 126.

The first target zone 210 and second target zone 502 may both beproduced in a similar manner to the embodiment shown and described inrelation to FIG. 8A, wherein the injection tube 218 is positionedsubstantially at the bottom of the first target zone 210 and/or secondtarget zone 502, and a production tube 216, or flow area within a casing602 annulus, receives the fluid 122 substantially at the top of thefirst target zone 210 and/or second target zone 502. Each target zone210, 502 may be divided into additional axially oriented target zones asillustrated in FIG. 8A. In a further embodiment, the system 100 may beconfigured to produce the second target zone 502 upon the substantialdepletion of the first target zone 210.

One of skill in the art will recognize that the proper combination ofinjection units 220, injection tubes 218, and production modules 216would allow the simultaneous production of multiple target zones 210,502 even within the same well 114. Such simultaneous production ismerely practicing multiple embodiments of the invention simultaneously,and is considered within the scope of the invention.

FIG. 10A is an illustration of a well spacing 1002 in accordance withthe present invention. FIG. 10A illustrates a first well 114 and asecond well 1014 that may comprise adjacent wells within an oil shalefield. The wells in the embodiment of FIG. 10A comprise a spacing 1002,or horizontal offset, of 200 feet, and a target zone thickness (TZT)1004 of 100 feet. The injected gas 122 propagates through the formation212 in a curve 1006, 1008 that approximates a normal distribution wherethe one-half width of each curve 1006, 1008 at the top of the targetzone 210 is approximately equal to the TZT 1004.

When the fluid 122 is injected at the proper pressure, the free water(if any) within the propagation curve 1006, 1008 inside the target zone210 is displaced by the injected fluid 122, and heating of the targetzone 210 can be achieved. The area above the injected gas 122propagation curve 1006, 1008 will be the primary area wherein kerogen isstripped from the target zone 210 and where the associated well 114,1014 will produce from. One example of a target zone 210 is overlaid onthe propagation curve 1006 in FIG. 10A to illustrate how the target zone210 and propagation curve 1006 may relate to each other.

In the embodiment of FIG. 10A, an unproduced area 1010 between the firstwell 114 and the second well 1014 is created due to the shape of the gaspropagation 1006, 1008 through the formation 212. However, the spacing1002 of the embodiment of FIG. 10A ensures that little or no formation212 volume is produced by more than one well, because there is little orno overlap between the first propagation curve 1006 and the secondpropagation curve 1008. The spacing 1002 of FIG. 10A will optimizing thedrilling and production costs per unit of oil produced. The spacing 1002of FIG. 10A maybe described as: S =2.0 * TZT, where S equals the wellspacing. In one embodiment, the spacing 1002 of FIG. 10A is appropriatewhere drilling and production costs dominate the economics of the system100.

FIG. 10B is an illustration of an alternate well spacing 1002 inaccordance with the present invention. FIG. 10B illustrates a first well114 and a second well 1014 that may comprise adjacent wells within anoil shale field. The wells in the embodiment of FIG. 10B comprise aspacing 1002 of 50 feet, and a TZT 1004 of 100 feet.

In the embodiment of FIG. 10B, an unproduced area 1010 between the firstwell 114 and the second well 1014 is created due to the shape of the gaspropagation 1006, 1008 through the formation 212. The unproduced area1010 for the embodiment of FIG. 10B is clearly small relative to theembodiment of FIG. 10A. A redundantly produced area 1012 between thefirst well 114 and the second well 1014 is created due to the shape ofthe gas propagation 1006, 1008 through the formation 212 and the closeproximity of the wells 114, 1014. The embodiment of FIG. 10Bapproximates the maximum recovery from the formation 212, as bringingthe wells 114, 1014 closer would yield little reduction in theunproduced area 1010 while significantly increasing the redundantlyproduced area 1012. The spacing of the embodiment of FIG. 10B may bedescribed as: S =0.5 *TZT. In one embodiment, the spacing of FIG. 10B isappropriate where the oil content of the formation 212 is high, and theprice of oil dominates the economics of the system 100.

It is within the skill of one in the art to determine an intermediatewell spacing between the embodiment of FIG. 10A and FIG. 10B based onthe specific economic factors for a given embodiment of the invention.Further, it is within the skill of one in the art to analogize the fluidpropagation shape 1006, 1008 to a horizontal well (refer to FIGS. 8A,8B, 9) to determine an optimal target zone 210, 502 size selection for agiven embodiment of the invention. In some situations, a well spacing1002 closer than the embodiment of FIG. 10B may be appropriate based onthe specific economic factors of a given embodiment of the invention,and such spacing is contemplated within the scope of the invention.

FIG. 11 is an illustration of a thermodynamic equilibrium chart forheavy hydrocarbons in the absence of excess hydrogen. As indicated byFIG. 11, heavier hydrocarbons, above 30 carbons per molecule, arefavored in the absence of excess hydrogen. FIG. 11 illustrates that atreatment module 128 operating in the absence of excess hydrogen is notexpected to crack most formation kerogen compositions into smallerhydrocarbon molecules.

FIG. 12 is an illustration of a thermodynamic equilibrium chart forheavy hydrocarbons in the presence of excess hydrogen. As indicated byFIG. 12, lighter hydrocarbons, around 10 carbons per molecule, arefavored in the presence of excess hydrogen. Significant improvements inlight hydrocarbon yield are achieved at all temperatures above about 65degrees C. for the hydrocarbon mix illustrated in FIG. 12, indicatingthat excess hydrocarbon is sufficient to favor light hydrocarbons at allreasonable operating temperatures. However, the reaction kinetics ofcracking a heavy hydrocarbon indicate that temperatures for thecatalytic reactor 302 need to be much higher than the minimum requiredto favor light hydrocarbons thermodynamically.

The exact temperatures required for an economically acceptable reactionspeed in hydrocarbon cracking depend upon the composition of the kerogenin the production fluid 126, the selected catalyst, the physical makeupof the catalytic reactor (size of the reactor, catalyst loading,catalyst bead pore size), and the flow rates of the production fluid126. These determinations are within the skill of on in the art forselecting a target temperature. A temperature requirement for a typicalsystem 100 will be greater than 350 degrees C. As with almost allcatalytic systems, some straightforward testing, within the skill of onein the art, is required to determine a target temperature for a specificproduction fluid 126 composition.

The schematic flow chart diagrams herein are generally set forth aslogical flow chart diagrams. As such, the depicted order and labeledsteps are indicative of one embodiment of the presented method. Othersteps and methods may be conceived that are equivalent in function,logic, or effect to one or more steps, or portions thereof, of theillustrated method. Additionally, the format and symbols employed areprovided to explain the logical steps of the method and are understoodnot to limit the scope of the method. Although various arrow types andline types may be employed in the flow chart diagrams, they areunderstood not to limit the scope of the corresponding method. Indeed,some arrows or other connectors may be used to indicate only the logicalflow of the method. For instance, an arrow may indicate a waiting ormonitoring period of unspecified duration between enumerated steps ofthe depicted method. Additionally, the order in which a particularmethod occurs may or may not strictly adhere to the order of thecorresponding steps shown.

FIG. 13 is a schematic flow diagram of a method 1300 for extracting oilfrom oil shale in accordance with the present invention. The method 1300may begin with a drilling unit 112 drilling 1302 at least one fluidconduit to a top of a target zone 210 and a bottom of the target zone210 of an oil shale formation 212. The stimulating module 116 maystimulate 1304 the target zone 210. A completion unit 118 may position1306 an injection tube 218 substantially at the bottom of the targetzone 210, and a position 1308 a production tube 216 substantially at thetop of the target zone 210.

The method 1300 may include an injection unit 120 injecting 1310 fluid122 into the target zone 210. Injecting 1310 the fluid 122 into thetarget zone 210 may include injecting the fluid 122 at a pressuregreater than the formation fluid pressure, and lower than the formationfracture pressure, such that the fluid 122 displaces free water withinthe formation.

A thermal delivery unit 124 may heat 132 the fluid 122 with a downholeburner 402 to generate a production fluid 126 with entrained kerogen.The production module 216 may produce 1314 the production fluid 126. Themethod 1300 may further include a treatment module 128 heating 1316 theproduction fluid 126 to a target temperature, and treating 1318 theproduction fluid 126 in a catalytic reactor 302 to reduce the averagemolecular weight of the entrained kerogen. Treating 1318 the productionfluid 126 may further include adding natural gas from a natural gasstorage facility 110 to the production fluid 126 such that a minimumestimated amount of hydrogen is available for reaction within thecatalytic reactor 302.

FIG. 14A is a schematic flow diagram of a method 1400 for extracting oilfrom an oil shale comprising a first and second target zone 210, 502 inaccordance with the present invention. The method 1400 may begin with adrilling unit 112 drilling 1402 at least one fluid conduit to a top anda bottom of a target zone 210. A completion unit 118 may set 1404 aproduction casing 602 across the target zone 210, and perforate 1406 thecasing 602 substantially at the top and at the bottom of the target zone210.

The stimulation module 116 may stimulate 1408 the target zone 210. Acompletion unit 118 may position 1410 an injection tube 218 in thecasing 602 substantially at the bottom of the target zone 210. Acirculation unit (not shown) may circulate 1412 the fluid 122 through anoffset well 702 with a depleted zone 704. A thermal delivery unit 124may heat 1414 the fluid 122 with a solar concentrator 136, and a gasburner 134.

The method 1400 may include an injection unit 120 injecting 1416 thefluid 122 into the target zone 210, where the fluid may heat and entrainkerogen within the target zone 210 to generate a production fluid 126. Aproduction tube 116 may produce 1418 the production fluid 126.

Referring to FIG. 14B, the method 1400 may continue with a stimulationmodule 116 stimulating 1420 a second target zone 502. An isolation unit(not shown) may isolate the first target zone 210. A completion unit 118may position 1424 the injection tube 118 substantially at the bottom ofthe second target zone 502. A circulation unit (not shown) may circulate1426 the fluid 122 through an offset well 702 with a depleted zone 704.A thermal delivery unit 124 may heat 1428 the fluid 122 with a solarconcentrator 136, and a gas burner 134. An injection unit 120 may inject1430 the fluid 122 into the second target zone 502 where the fluid 122may heat and entrain kerogen within the second target zone 502 togenerate a production fluid 126. The production tube 116 may produce1432 the production fluid 126.

FIG. 15A is a schematic flow diagram of a method 1500 for extracting oilfrom an oil shale. The method 1500 may begin with a drilling unit 112drilling 1502 a first horizontal well segment 802 in fluid communicationwith the top of a target zone 210, and a second horizontal well segment804 in fluid communication with the bottom of the target zone 210. Themethod 1500 may include a stimulation module 116 stimulating 1504 thetarget zone 210, and a completion unit 118 positioning 1506 an injectiontube 218 substantially at the bottom of the target zone 210.

The method 1500 may include an injection unit 120 injecting 1508 fluid122 into the target zone 210, and a thermal delivery unit 124 heating 1510 the fluid 122 such that the heated fluid 122 entrains kerogen togenerate a production fluid 126. The method 1500 may include aproduction tube 216 producing 1512 the production fluid 126. The method1500 may continue with the drilling unit 112 drilling 1514 a thirdhorizontal well segment 902 in fluid communication with a top of asecond target zone 502, where the first horizontal well segment 802 isin fluid communication with the bottom of the second target zone 502.

Referring to FIG. 15B, the stimulation module 116 may stimulate 1516 thesecond target zone 502. The completion unit 118 may position 1518 aninjection tube 218 substantially at the bottom of the second target zone502. The method 1500 may include an isolation unit (not shown) isolating1520 the fluid conduit in communication with the first target zone 804from the fluid conduits in communication with the second target zone802, 902.

The method 1500 may include the injection unit 120 injecting 1508 fluid122 into the second target zone 502, and a thermal delivery unit 124heating 1510 the fluid 122 such that the heated fluid 122 entrainskerogen to generate a production fluid 126. The method 1500 may includea production tube 216 producing 1512 the production fluid 126.

From the foregoing discussion, it is clear that the invention provides asystem, method, and apparatus for in-situ extraction of oil from an oilshale. The invention overcomes previous limitations in the art byproviding an energy efficient process utilizing inexpensive completiontechniques to produce the oil in an environmentally sound manner.

The present invention may be embodied in other specific forms withoutdeparting from its spirit or essential characteristics. The describedembodiments are to be considered in all respects only as illustrativeand not restrictive. The scope of the invention is, therefore, indicatedby the appended claims rather than by the foregoing description. Allchanges which come within the meaning and range of equivalency of theclaims are to be embraced within their scope.

1. An apparatus for extracting oil from oil shale, the apparatuscomprising: a drilling unit configured to drill at least one fluidconduit to a top of a target zone and a bottom of the target zone of anoil shale formation; a stimulation module configured to stimulate thetarget zone; a completion unit configured to position an injection tubesubstantially at the bottom of the target zone; an injection unitconfigured to inject a fluid into the target zone; a thermal deliveryunit configured to heat the fluid such that the heated fluid entrainsin-situ kerogen to generate a production fluid; and a production moduleto produce the production fluid.
 2. The apparatus of claim 1, whereinthe injection unit is further configured to inject the fluid into thetarget zone such that the fluid displaces free water within the targetzone.
 3. The apparatus of claim 1, wherein the thermal delivery unit isfurther configured to heat the fluid such that the fluid temperatureexceeds 300 degrees C. at the bottom of the target zone.
 4. Theapparatus of claim 1, wherein the thermal delivery unit is furtherconfigured to heat the fluid such that the fluid temperature exceeds 400degrees C. at the bottom of the target zone.
 5. The apparatus of claim1, wherein the thermal delivery unit is further configured to heat thefluid at the surface, and wherein the injection tube comprises a vacuuminsulated tube.
 6. The apparatus of claim 5, wherein heating the fluidat the surface comprises heating the fluid with at least one solarconcentrator.
 7. The apparatus of claim 5, wherein heating the fluid atthe surface comprises heating the fluid with a natural gas burner. 8.The apparatus of claim 1, wherein the thermal delivery unit comprises adownhole burner configured to heat the fluid within the at least onefluid conduit.
 9. The apparatus of claim 1, further comprising atreatment module configured to heat the production fluid to a targettemperature and to react the production fluid in a catalytic reactor.10. The apparatus of claim 9, wherein the target temperature comprises atemperature greater than 350 degrees Celsius.
 11. The apparatus of claim1 wherein the drilling unit comprises a coiled tubing drilling unit. 12.The apparatus of claim 1, wherein the stimulation module comprises anexplosive.
 13. The apparatus of claim 1, wherein the production modulecomprises a production tube positioned substantially at the top of thetarget zone.
 14. The apparatus of claim 1, wherein: the target zonecomprises a first target zone; wherein the stimulation module is furtherconfigured to stimulate a second target zone; wherein the completionunit is further configured to position the injection tube substantiallyat the bottom of the second target zone; the apparatus furthercomprising an isolation unit configured to isolate the at least onefluid conduit from the first target zone; wherein the injection unit isfurther configured to inject the fluid into the second target zone; andwherein the thermal delivery unit is further configured to heat thefluid such that energy of the heated fluid entrains in-situ kerogenwithin the second target zone to generate the production fluid.
 15. Theapparatus of claim 14, wherein the isolation unit comprises one of abridge plug and a cement plug.
 16. A method for extracting oil from oilshale, the method comprising: drilling at least one fluid conduit to atop of a target zone and a bottom of the target zone of an oil shaleformation; stimulating the target zone; positioning an injection tubesubstantially at the bottom of the target zone; injecting a fluid intothe target zone; heating the fluid such that the heated fluid entrainsin-situ kerogen to generate a production fluid; and producing theproduction fluid.
 17. The method of claim 16, wherein injecting fluidinto the target zone further comprises injecting the fluid into thetarget zone at a pressure higher than a formation fluid pressure andlower than a formation fracture pressure, such that the fluid displacesfree water within the target zone.
 18. The method of claim 16, furthercomprising heating the production fluid to a target temperature, andtreating the production fluid in a catalytic reactor to reduce theaverage molecular weight of the entrained kerogen.
 19. The method ofclaim 18, further comprising adding natural gas to the production fluidsuch that a minimal amount of hydrogen is available for reaction withinthe catalytic reactor.
 20. The method of claim 16, further comprisingpositioning a production tube substantially at the top of the targetzone, and wherein producing the production fluid comprises flowing theproduction fluid up the production tubing.
 21. The method of claim 16,further comprising setting a production casing through the oil shaleformation, perforating the production casing substantially near thebottom of the target zone, perforating the production casingsubstantially near the top of the target zone, wherein positioning theinjection tube further comprises positioning the injection tube withinthe production casing, and wherein producing the production fluidcomprises flowing the production fluid up the annulus formed between theproduction casing and the injection tubing.
 22. The method of claim 21,wherein flowing the production fluid up the annulus formed by the casingand the injection tube comprises flowing the product up a productiontube within the annulus.
 23. The method of claim 16, wherein the fluidcomprises natural gas.
 24. The method of claim 23, wherein heating thefluid comprises at least one member selected from the group consistingof heating the fluid with a solar concentrator, and heating the fluidwith a gas burner configured to burn a portion of the production fluid.25. The method of claim 23, wherein heating the fluid comprisescirculating the fluid through a substantially depleted zone in an offsetwell, the substantially depleted zone comprising a shale formationsubstantially depleted of kerogen.
 26. The method of claim 16, whereinthe fluid comprises at least one member selected from the groupconsisting of methane, ethane, propane, butane, hydrocarbon gas,hydrogen, carbon monoxide, nitrogen, helium, argon, and neon.
 27. Themethod of claim 16, wherein heating the fluid comprises heating thefluid with a downhole burner within the at least one fluid conduit. 28.The method of claim 16, wherein drilling at least one fluid conduit to atop of a target zone and a bottom of the target zone of an oil shaleformation comprises drilling a vertical well through the oil shaleformation, and wherein the target zone comprises a target zone thickness(TZT).
 29. The method of claim 28, wherein the TZT comprises a thicknessbetween 25 feet and 100 feet.
 30. The method of claim 28, furthercomprising drilling a plurality of vertical wells through the oil shaleformation, wherein each of the plurality of vertical wells is spaced ata distance between about 0.5 times the TZT and about 2.0 times the TZT.31. The method of claim 28, wherein the target zone comprises a firsttarget zone, the method further comprising stimulating a second targetzone, positioning the injection tube substantially at the bottom of thesecond target zone, isolating the at least one fluid conduit from thefirst target zone, injecting the fluid into the second target zone,heating the fluid such that the heated fluid entrains in-situ kerogenwithin the second target zone to generate a production fluid, andproducing the production fluid.
 32. The method of claim 16, whereindrilling at least one fluid conduit to a top of a target zone and abottom of the target zone of an oil shale formation comprises drilling afirst horizontal well segment in fluid communication with the topportion of the target zone, and drilling a second horizontal wellsegment in fluid communication with the bottom portion of the targetzone.
 33. The method of claim 32, wherein the target zone comprises ahorizontal width equal to the height of the target zone.
 34. The methodof claim 32, wherein the target zone comprises a first target zone,further comprising drilling a third horizontal well segment in fluidcommunication with the top portion of a second target zone, wherein thefirst horizontal well segment is in fluid communication with a bottomportion of the second target zone, the method further comprisingstimulating the second target zone, positioning the injection tubesubstantially at the bottom of the second target zone, isolating the atleast one fluid conduit from the first target zone, injecting the fluidinto the second target zone, heating the fluid such that the heatedfluid entrains in-situ kerogen within the second target zone to generatethe production fluid, and producing the production fluid.
 35. A systemfor in-situ extraction of oil from oil shale, the system comprising: athree-phase separator configured to separate a production fluid intooil, water, and natural gas; fluid coupling configured to deliverseparated water to a water disposal system, to deliver separated oil toan oil storage facility, and to deliver separated natural gas to anatural gas storage facility; a drilling unit configured to drill atleast one fluid conduit to a top of a target zone and a bottom of thetarget zone of an oil shale formation; a stimulation module configuredto stimulate the target zone; a completion unit configured to positionan injection tube substantially at the bottom of the target zone; aninjection unit configure to inject a fluid into the target zone; athermal delivery unit configured to heat the fluid such that the heatedfluid entrains in-situ kerogen to generate a product fluid; a productionmodule to produce the production fluid; a treatment module configured toheat the production fluid to a target temperature and to react theproduction fluid in a catalytic reactor; and a condensing moduleconfigured to cool the reacted production fluid and to deliver thereacted production fluid to the three-phase separator.
 36. The system ofclaim 35, further comprising an oil heater configured to receive heatfrom a solar concentrator and to receive heat from a natural gas burner,wherein the thermal delivery unit is further configured to heat thefluid using heat from the oil heater, and wherein the injection tubecomprises a vacuum insulated tube.